Non-Extruding Single Packer

ABSTRACT

An inflatable packer assembly for conveyance and adjustment within a wellbore. The inflatable packer assembly includes a first end assembly, a second end assembly, and a mandrel extending between the first and second end assemblies and comprising a fluid port on an outer surface of the mandrel. The inflatable packer assembly further includes an expandable packer disposed around the mandrel and sealingly connected with one or both of the first and second end assemblies. At least a portion of the first end assembly extends around the mandrel to define an annular space between the first end assembly and the mandrel. The fluid port extends to the annular space and passes a fluid to inflate the expandable packer.

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application claims priority to, and the benefit of theearlier filing date of, EP Patent Application No. 17306304.1, titled“Packer Adjustment Downhole,” filed Sep. 29, 2017, the entirety of whichis hereby incorporated herein by reference.

BACKGROUND OF THE DISCLOSURE

In the oil and gas industry, many downhole tools include expandableinflatable packers. For example, a dual-packer tool may be positioned atan intended location within a wellbore, and elastomeric sealing elementsof the packers are radially expanded to form an annular seal with thewellbore wall or a casing lining the wellbore to fluidly isolatesections of the wellbore between the packers. Similar operations mayutilize a three-dimensional radial packer havingcircumferentially-spaced fluid inlets integrated with the elastomericsealing element of a single packer.

Such dual- and single-packer tools can have limited deflationefficiency, and may mostly rely on the elastomeric properties at hightemperature. Rubber tends to creep when exposed to stress and hightemperature, such that it can be difficult to force deflation back tothe initial, unexpanded diameter without removing the tool from thewellbore. Some packer tools include retraction mechanisms and/or otherdevices, such as may be attached to an extremity of the packer to applya deflation force, but such devices have had limited effectiveness.

Additionally, while deflating the packer may be achieved by pumpinginflation fluid out of the packer until the packer is again compressedagainst the support structure of the downhole tool, this operation canbe dangerous because the packer can be accidentally put in negativepressure, such that hydrostatic pressure is above inflation fluidpressure. When this situation occurs, the packer is often damaged when arubber inner bladder of the packer is forced into or extruded through ahole, port, or an asperity on an outer surface of the support structure.

SUMMARY OF THE DISCLOSURE

This summary is provided to introduce a selection of concepts that arefurther described below in the detailed description. This summary is notintended to identify indispensable features of the claimed subjectmatter, nor is it intended for use as an aid in limiting the scope ofthe claimed subject matter.

The present disclosure introduces an apparatus including an inflatablepacker assembly for coupling within a tool string conveyed within awellbore. The inflatable packer assembly includes a mandrel comprising,a first connector assembly, a second connector assembly, and anexpandable packer. The mandrel includes a port in an outer surface ofthe mandrel, and a flowline extending within the mandrel and in fluidcommunication with the port. The first connector assembly is connectedto the mandrel such that the port is axially disposed between opposingends of the first connector assembly. The first connector assembly isfor coupling with a first portion of the tool string such that a secondflowline of the first portion is in fluid communication with the firstflowline. The second connector assembly is for coupling with a secondportion of the tool string. The expandable packer is disposed around themandrel and connected with the first and second connector assemblies,such that fluid received from the first and second flowlines via theport expands the expandable packer against a sidewall of the wellbore ora casing within the wellbore.

The present disclosure also introduces an apparatus including aninflatable packer assembly for conveyance within a wellbore. Theinflatable packer assembly includes a first end assembly, a second endassembly, a mandrel, and an expandable packer. The mandrel extendsbetween the first and second end assemblies and includes a fluid port onan outer surface of the mandrel. At least a portion of the first endassembly extends around the mandrel to define an annular space betweenthe first end assembly and the mandrel. The fluid port extends to theannular space. The expandable packer is disposed around the mandrel andsealingly connected with the first and second end assemblies. The fluidport and annular space pass a fluid to inflate the expandable packer.

The present disclosure also introduces a method including coupling aninflatable packer assembly to a tool string. The inflatable packerassembly includes a mandrel, a first connector assembly, a secondconnector assembly, and an expandable packer. The mandrel includes aport in an outer surface of the mandrel, and a first flowline extendingwithin the mandrel and in fluid communication with the port. The firstconnector assembly is connected to the mandrel such that the port isaxially disposed between opposing ends of the first connector assembly.The expandable packer is disposed around the mandrel and connected withthe first and second connector assemblies. Coupling the inflatablepacker assembly to the tool string includes coupling the first connectorassembly with a first portion of the tool string such that a secondflowline of the first portion of the tool string is in fluidcommunication with the first flowline, and coupling the second connectorassembly with a second portion of the tool string. The method alsoincludes conveying the inflatable packer assembly within a wellbore to aselected location along the wellbore, and inflating the expandablepacker away from the mandrel to against a sidewall of the wellbore, or acasing within the wellbore, by transferring a fluid into the expandablepacker through the first flowline, the second flowline, and the port.

These and additional aspects of the present disclosure are set forth inthe description that follows, and/or may be learned by a person havingordinary skill in the art by reading the material herein and/orpracticing the principles described herein. At least some aspects of thepresent disclosure may be achieved via means recited in the attachedclaims.

BRIEF DESCRIPTION OF THE DRAWINGS

The present disclosure is understood from the following detaileddescription when read with the accompanying figures. It is emphasizedthat, in accordance with the standard practice in the industry, variousfeatures are not drawn to scale. In fact, the dimensions of the variousfeatures may be arbitrarily increased or reduced for clarity ofdiscussion.

FIG. 1 is a schematic view of at least a portion of an exampleimplementation of apparatus according to one or more aspects of thepresent disclosure.

FIG. 2 is a schematic view of at least a portion of an exampleimplementation of apparatus according to one or more aspects of thepresent disclosure.

FIG. 3 is a schematic view of at least a portion of an exampleimplementation of apparatus according to one or more aspects of thepresent disclosure.

FIG. 4 is a side view of at least a portion of an example implementationof apparatus according to one or more aspects of the present disclosure.

FIG. 5 is a sectional view of a portion of the apparatus shown in FIG. 4according to one or more aspects of the present disclosure.

FIG. 6 is a schematic view of at least a portion of an exampleimplementation of apparatus according to one or more aspects of thepresent disclosure.

FIG. 7 is a flow-chart diagram of at least a portion of an exampleimplementation of a method related to one or more aspects of the presentdisclosure.

FIG. 8 is a flow-chart diagram of at least a portion of an exampleimplementation of a method according to one or more aspects of thepresent disclosure.

FIG. 9 is a flow-chart diagram of at least a portion of an exampleimplementation of a method according to one or more aspects of thepresent disclosure.

DETAILED DESCRIPTION

It is to be understood that the following disclosure provides manydifferent examples for different features and other aspects of variousimplementations. Specific examples of components and arrangements aredescribed below to simplify the present disclosure. These are merelyexamples, and are not intended to be limiting. In addition, the presentdisclosure may repeat reference numerals and/or letters in the variousexamples. This repetition is for simplicity and clarity, and does not initself dictate a relationship between the various implementationsdescribed below.

FIG. 1 is a schematic view of an example wellsite system 100 to whichone or more aspects of the present disclosure may be applicable. Thewellsite system 100 may be onshore or offshore. In the example wellsitesystem 100 shown in FIG. 1, a wellbore 104 is formed in one or moresubterranean formations 102 by rotary drilling. Other example systemswithin the scope of the present disclosure may also or instead utilizedirectional drilling. While some elements of the wellsite system 100 aredepicted in FIG. 1 and described below, it is to be understood that thewellsite system 100 may include other components in addition to, orinstead of, those presently illustrated and described.

As shown in FIG. 1, a drillstring 112 suspended within the wellbore 104comprises a bottom hole assembly (BHA) 140 that includes or is coupledwith a drill bit 142 at its lower end. The surface system includes aplatform and derrick assembly 110 positioned over the wellbore 104. Theplatform and derrick assembly 110 may comprise a rotary table 114, akelly 116, a hook 118, and a rotary swivel 120. The drillstring 112 maybe suspended from a lifting gear (not shown) via the hook 118, with thelifting gear being coupled to a mast (not shown) rising above thesurface. An example lifting gear includes a crown block affixed to thetop of the mast, a vertically traveling block to which the hook 118 isattached, and a cable passing through the crown block and the verticallytraveling block. In such an example, one end of the cable is affixed toan anchor point, whereas the other end is affixed to a winch to raiseand lower the hook 118 and the drillstring 112 coupled thereto. Thedrillstring 112 comprises one or more types of tubular members, such asdrill pipes, threadedly attached one to another, perhaps including wireddrilled pipe.

The drillstring 112 may be rotated by the rotary table 114, whichengages the kelly 116 at the upper end of the drillstring 112. Thedrillstring 112 is suspended from the hook 118 in a manner permittingrotation of the drillstring 112 relative to the hook 118. Other examplewellsite systems within the scope of the present disclosure may utilizea top drive system to suspend and rotate the drillstring 112, whether inaddition to or instead of the illustrated rotary table system.

The surface system may further include drilling fluid or mud 126 storedin a pit or other container 128 formed at the wellsite. The drillingfluid 126 may be oil-based mud (OBM) or water-based mud (WBM). A pump130 delivers the drilling fluid 126 to the interior of the drillstring112 via a hose or other conduit 122 coupled to a port in the rotaryswivel 120, causing the drilling fluid to flow downward through thedrillstring 112, as indicated in FIG. 1 by directional arrow 132. Thedrilling fluid exits the drillstring 112 via ports in the drill bit 142,and then circulates upward through the annulus region between theoutside of the drillstring 112 and the wall 106 of the wellbore 104, asindicated in FIG. 1 by directional arrows 134. In this manner, thedrilling fluid 126 lubricates the drill bit 142 and carries formationcuttings up to the surface as it is returned to the container 128 forrecirculation.

The BHA 140 may comprise one or more specially made drill collars nearthe drill bit 142. Each such drill collar may comprise one or moredevices permitting measurement of downhole drilling conditions and/orvarious characteristic properties of the subterranean formation 102intersected by the wellbore 104. For example, the BHA 140 may compriseone or more logging-while-drilling (LWD) modules 144, one or moremeasurement-while-drilling (MWD) modules 146, a rotary-steerable systemand motor 148, and perhaps the drill bit 142. Other BHA components,modules, and/or tools are also within the scope of the presentdisclosure, and such other BHA components, modules, and/or tools may bepositioned differently in the BHA 140 than as depicted in FIG. 1.

The LWD modules 144 may comprise one or more devices for measuringcharacteristics of the formation 102, including for obtaining a sampleof fluid from the formation 102. The MWD modules 146 may comprise one ormore devices for measuring characteristics of the drillstring 112 and/orthe drill bit 142, such as for measuring weight-on-bit, torque,vibration, shock, stick slip, tool face direction, and/or inclination,among other examples. The MWD modules 146 may further comprise anapparatus 147 for generating electrical power to be utilized by thedownhole system, such as a mud turbine generator powered by the flow ofthe drilling fluid 126. Other power and/or battery systems may also orinstead be employed. One or more of the LWD modules 144 and/or the MWDmodules 146 may be or comprise at least a portion of a packer tool asdescribed below.

The wellsite system 100 also includes a data processing system that caninclude one or more, or portions thereof, of the following: the surfaceequipment 190, control devices and electronics in one or more modules ofthe BHA 140 (such as a downhole controller 150), a remote computersystem (not shown), communication equipment, and other equipment. Thedata processing system may include one or more computer systems ordevices and/or may be a distributed computer system. For example,collected data or information may be stored, distributed, communicatedto a human wellsite operator, and/or processed locally or remotely.

The data processing system may, individually or in combination withother system components, perform the methods and/or processes describedbelow, or portions thereof. Methods and/or processes within the scope ofthe present disclosure may be implemented by one or more computerprograms that run in a processor located, for example, in one or moremodules of the BHA 140 and/or the surface equipment 190. Such programsmay utilize data received from the BHA 140 via mud-pulse telemetryand/or other telemetry means, and/or may transmit control signals tooperative elements of the BHA 140. The programs may be stored on atangible, non-transitory, computer-usable storage medium associated withthe one or more processors of the BHA 140 and/or surface equipment 190,or may be stored on an external, tangible, non-transitory,computer-usable storage medium that is electronically coupled to suchprocessor(s). The storage medium may be one or more known orfuture-developed storage media, such as a magnetic disk, an opticallyreadable disk, flash memory, or a readable device of another kind,including a remote storage device coupled over a communication link,among other examples.

FIG. 2 is a schematic view of another example wellsite system 200 towhich one or more aspects of the present disclosure may be applicable.The wellsite system 200 may be onshore or offshore. In the examplewellsite system 200 shown in FIG. 2, a tool string 204 is conveyed intothe wellbore 104 via a conveyance means 208, which may be or comprise awireline, a slickline, or a fluid conduit, such as coiled tubing,completion tubing, a liner, or a casing. As with the wellsite system 100shown in FIG. 1, the example wellsite system 200 of FIG. 2 may beutilized for evaluation of the wellbore 104 and/or the formation 102penetrated by the wellbore 104.

The tool string 204 is suspended in the wellbore 104 from the lower endof the conveyance means 208, which may be a multi-conductor loggingcable spooled on a surface winch (not shown). The conveyance means 208may include at least one conductor that facilitates data communicationbetween the tool string 204 and surface equipment 290 disposed on thesurface. The surface equipment 290 may have one or more aspects incommon with the surface equipment 190 shown in FIG. 1.

The tool string 204 and conveyance means 208 may be structured andarranged with respect to a service vehicle (not shown) at the wellsite.For example, the conveyance means 208 may be connected to a drum (notshown) at the wellsite surface, such that rotation of the drum may raiseand lower the tool string 204. The drum may be disposed on a servicevehicle or a stationary platform. The service vehicle or stationaryplatform may further contain the surface equipment 290.

The tool string 204 comprises one or more elongated housings encasingvarious electronic components and modules schematically represented inFIG. 2. For example, the illustrated tool string 204 includes severalmodules 212, at least one of which may be or comprise at least a portionof a packer tool as described below. Other implementations of thedownhole tool string 204 within the scope of the present disclosure mayinclude additional or fewer components or modules relative to theexample implementation depicted in FIG. 2.

The wellsite system 200 also includes a data processing system that caninclude one or more, or portions thereof, of the following: the surfaceequipment 290, control devices and electronics in one or more modules ofthe tool string 204 (such as a downhole controller 216), a remotecomputer system (not shown), communication equipment, and otherequipment. The data processing system may include one or more computersystems or devices and/or may be a distributed computer system. Forexample, collected data or information may be stored, distributed,communicated to a human wellsite operator, and/or processed locally orremotely.

The data processing system may, whether individually or in combinationwith other system components, perform the methods and/or processesdescribed below, or portions thereof. Methods and/or processes withinthe scope of the present disclosure may be implemented by one or morecomputer programs that run in a processor located, for example, in oneor more modules 212 of the tool string 204 and/or the surface equipment290. Such programs may utilize data received from the downholecontroller 216 and/or other modules 212 via the conveyance means 208,and may transmit control signals to operative elements of the toolstring 204. The programs may be stored on a tangible, non-transitory,computer-usable storage medium associated with the one or moreprocessors of the downhole controller 216, other modules 212 of the toolstring 204, and/or the surface equipment 290, or may be stored on anexternal, tangible, non-transitory, computer-usable storage medium thatis electronically coupled to such processor(s). The storage medium maybe one or more known or future-developed storage media, such as amagnetic disk, an optically readable disk, flash memory, or a readabledevice of another kind, including a remote storage device coupled over acommunication link, among other examples.

While FIGS. 1 and 2 illustrate example wellsite systems 100 and 200,respectively, that convey a downhole tool/string into the wellbore 104,other example implementations consistent with the scope of thisdisclosure may utilize other conveyance means to convey tools/stringsinto the wellbore 104. Additionally, other downhole tools within thescope of the present disclosure may comprise components in a non-modularconstruction also consistent with the scope of this disclosure.

FIG. 3 is a schematic view of at least a portion of an exampleimplementation of an inflatable packer tool 300 configured to beconveyed within a wellbore according to one or more aspects of thepresent disclosure. The packer tool 300 may be implemented as one ormore of the LWD modules 144 or MWD modules 146 shown in FIG. 1, and/orone or more of the modules 212 shown in FIG. 2, and may thus be conveyedwithin the wellbore 104 via a wireline, a slickline, a drillstring,coiled tubing, completion tubing, a liner, a casing, and/or otherconveyance means. As described below, the packer tool 300 is an assemblyof a plurality of components operating together in a coordinated mannerand, thus, may also be referred to as a packer assembly.

The inflatable packer tool 300 comprises a first end assembly 310 at afirst end of the packer tool 300, and a second end assembly 312 at anopposing second end of the packer tool 300. The end assemblies 310, 312may be or comprise connector assemblies, such as may be configured tocouple the packer tool 300 within a tool string. For example, the endassembly 310 may be coupled with a first (e.g., uphole) portion 302 ofthe tool string, and the end assembly 312 may be coupled with a second(e.g., downhole) portion 304 of the tool string. The tool string may bethe BHA 140 shown in FIG. 1, the tool string 204 shown in FIG. 2, and/orother tool strings within the scope of the present disclosure.

A mandrel 314 (e.g., a tube) extends between the end assemblies 310,312. The first and/or second end assembly 310, 312 may be connected(e.g., fixedly, slidably) with the mandrel 314, and at least a portionof the first and/or second end assembly 310, 312 may extend around themandrel 314. An inflatable (e.g., flexible, elastic) packer 316 isdisposed around the mandrel 314, and may be sealingly connected with oneor both of the end assemblies 310, 312. In a fully deflated (i.e.,retracted) state of the packer 316, an inner surface of the packer 316may be disposed against and/or in contact with an outer profile (e.g.,surface) of the mandrel 314. In an inflated (i.e., expanded) state ofthe packer 316, the inner surface of the packer 316 may be disposed awayfrom the outer profile of the mandrel 314 and an outer surface of thepacker 316 may be disposed against a sidewall of the wellbore or acasing within the wellbore to fluidly seal a portion of the wellboreand/or to maintain the packer tool 300 in position within the wellbore.

The mandrel 314 comprises a fluid port 318 on an outer surface of themandrel 314, and a flowline 320 extending within the mandrel 314 and influid communication with the port 318. The port 318 may be axiallydisposed between opposing axial ends 320, 322 of the end assembly 310such that at least a portion of the end assembly 310 extends around orcovers the port 318.

The outer profile of the mandrel 314, including one or more outersurfaces of the mandrel 314, may be substantially smooth along a lengthof the mandrel 314 extending between the end assemblies 310, 312. Forexample, a length of the mandrel 314 that is not surrounded by the endassemblies 310, 312 may be substantially cylindrical and not includeadditional ports, depressions, holes, asperities, protrusions, and/orother irregularities. The outer profile of the mandrel 314 may also orinstead be substantially smooth along a length of the mandrel 314between the port 318 and the end assembly 312. Thus, the outer profileof the mandrel 314 may be substantially smooth along a length of themandrel 314 that is directly surrounded by, disposed against, orcontacts the packer 316 when the packer 316 is deflated.

The portion 302 of the tool string may comprise a fluid pump 306 fluidlyconnected with a flowline 308 extending axially along the portion 302 ofthe tool string. When the end assembly 310 is coupled with the portion302 of the tool string, the flowlines 308, 320 are fluidly connected tofluidly connect the pump 306 with the flowline 320 and the port 318.Accordingly, during downhole operations (e.g., fluid samplingoperations), the pump 306 may pump (i.e., discharge) a fluid (e.g.,inflation fluid) into the packer 316 via the flowlines 308, 320 and theport 318 to expand the packer 316 away from the mandrel 314 to againstthe sidewall of the wellbore or the casing within the wellbore. The pump306 may also pump (i.e., draw) the fluid out of the packer 316 via theflowlines 308, 320 and the port 318 to retract the packer 316 away fromthe sidewall of the wellbore or the casing toward and into contact withthe mandrel 314.

Although not shown, the packer tool 300 may comprise multiple instancesof the port 318 distributed circumferentially around the mandrel 314(i.e., along an outer surface of the mandrel 314), each located betweenthe opposing ends 320, 322 of the end assembly 310 and connected withthe flowline 320. Although not shown, the packer tool 300 may also orinstead comprise one or more fluid ports located between the opposingends of the end assembly 312, each connected with the flowline 320 oranother flowline extending through the mandrel 314. Accordingly, thepacker 316 may be inflated and deflated from one or both ends of thepacker 316.

FIG. 3 further shows a port 319 (drawn in phantom lines) on an outersurface of the mandrel 314 and a flowline 321 (drawn in phantom lines)extending within the mandrel 314 and in fluid communication with theport 319. The port 319 and the flowline 321 are not part of the packertool 300, but are shown in FIG. 3 to indicate the location of the port319 in conventional packer tools. Namely, the port 319 is located alongthe mandrel 314 adjacent to the packer 316, such that when the packer316 is fully deflated (i.e., retracted), the inner surface of the packer316 is disposed against and/or in contact with the port 319. Suchlocation of the port 319 may cause an inner layer (e.g., a rubber layer)of the packer 316 to be forced into and/or extruded through the port319, damaging the inner layer. Such situation may take place when thehydrostatic pressure within the wellbore is greater than the pressurewithin the packer 316, for example, when the hydrostatic pressure isgreater than the pressure of the fluid within the flowline 321.

FIG. 4 is a side view of at least a portion of an example implementationof a packer tool 400 according to one or more aspects of the presentdisclosure. The packer tool 400 may be implemented as one or more of theLWD modules 144 or MWD modules 146 shown in FIG. 1, one or more of themodules 212 shown in FIG. 2, and/or the packer tool 300 shown in FIG. 3,and may thus be conveyed within the wellbore 104 via a conveyance meansdescribed in association with FIGS. 1-3. An uphole portion of the packertool 400 includes an uphole connector assembly 402 comprising a nipple410, a lock ring 412, and a retainer 414, which collectively retain anuphole portion of an expandable packer 416. A downhole portion of thepacker tool 400 may similarly include a downhole connector assembly 404comprising a nipple 418, a lock ring 420, and a retainer 422collectively retaining a downhole portion of the packer 416. The upholeconnector assembly 402 may be configured to couple the packer tool 400to an uphole portion 406 (shown in FIG. 5) of a tool string, and thedownhole connector assembly 404 may be configured to couple the packertool 400 to a downhole portion (not shown) of the tool string. Suchmeans retaining the uphole and/or downhole portions of the packer 416may move axially relative to a mandrel 424 (e.g., a tube) (shown in FIG.5) of the packer tool 400. However, the scope of the present disclosurealso includes impementations in which means other than as describedabove are utilized to retain the packer 416.

FIG. 5 is a sectional view of an uphole portion of the packer tool 400shown in FIG. 4 according to one or more aspects of the presentdisclosure. The nipple 410 may be coupled with the mandrel 424 viathreads, fasteners, interference/press fit, and/or other means. Thenipple 410 may instead also be slidably coupled with the mandrel 424,such as may permit the nipple 410 and, thus, the connector assembly 402to slide axially along the mandrel 424 in an axially inward direction426 when the packer 416 is being inflated, and in an axially outwarddirection 428 when the packer 416 is being deflated. The nipple 410 maypartially extend into an uphole end 430 of the packer 416. For example,the uphole end 430 of the packer 416 may abut a downhole-facing shoulder432 of the nipple 410. A crimped skirt 434 and the nipple 410 maycooperatively secure an uphole portion of the packer 416, such as viacorresponding external undulations 436 of the nipple 410 and internalundulations 438 of the crimped skirt 434. The retainer 414 may securethe crimped skirt 434 in the position depicted in FIG. 5, and the lockring 412 may threadedly or otherwise couple the retainer 414 to thenipple 410.

The packer 416 is disposed around the mandrel 424 and may comprise oneor more of an inner elastic layer 440, an inner support layer 442, anouter elastic layer 444, an outer support layer 446, and an intermediatelayer 448. The inner elastic layer 440 may be formed of rubber and/orother elastic materials. The inner support layer 442 may be at leastpartially adhered to the inner elastic layer 440, and may be formed ofrubber, metal, and/or other materials. The outer elastic layer 444 maybe formed of rubber and/or other elastic materials that may be utilizedto sealingly engage a wellbore or casing sidewall. The outer supportlayer 446 may be at least partially adhered to the outer elastic layer444 and/or the inner support layer 442, and may be formed of rubber,metal, and/or other materials. The intermediate layer 448 is retainedbetween the inner and outer support layers 442, 446, and at least aportion of the intermediate layer 448 may be adhered to the inner and/orouter support layers 442, 446. The intermediate layer 448 may comprisecables made of metal and/or other materials.

The mandrel 424 extends between the connector assemblies 402, 404, andat least a portion of the uphole and/or downhole connector assembly 402,404 may extend around the mandrel 424. In a fully deflated (i.e.,retracted) state of the packer 416, an inner surface 450 of the packer416 (i.e., inner surface of the inner elastic layer 440) may be disposedagainst and/or in contact with an outer profile 452 (e.g., outersurface) of the mandrel 424. In an inflated (i.e., expanded) state ofthe packer 416, the inner surface 450 of the packer 416 may be disposedaway from the outer profile 452 of the mandrel 424, forming an internalspace (i.e., volume) (not shown) between the mandrel 424 and the packer416. In the inflated state, an outer surface 454 of the packer 416(i.e., outer surface of the outer elastic layer 444) may be disposedagainst a sidewall of the wellbore or a casing within the wellbore tofluidly seal a portion of the wellbore and/or to maintain the packertool 400 in position within the wellbore.

The mandrel 424 has a fluid port 456 on an outer surface of the outerprofile 452 of the mandrel 424, and a flowline 458 (e.g., a fluidpassage) extending longitudinally within the mandrel 424 and in fluidcommunication with the port 456. As further described below, theflowline 458 may be configured to transfer a fluid from an upholeportion 406 of the tool string to inflate the packer 416. The mandrel424 may also have an axial passage 460 extending longitudinally withinthe mandrel 424. The axial passage 460 may be configured to transfer afluid through the packer tool 400 between the opposing ends of the toolstring connected with the packer tool 400. The port 456 may be axiallydisposed between opposing axial ends 462, 464 of the connector assembly402, such that at least a portion of the connector assembly 402 extendsaround or covers the port 456. For example, the nipple 410 of theconnector assembly 410 may comprise an elongated collar or sleeve 411extending around or covering the port 456. A portion of the nipple 410,including the sleeve 411, may have an inner profile 465 (e.g., an innersurface) with an inner diameter 466 that is larger than an outerdiameter 468 of the outer profile 452 of the mandrel 424 and, thus, maynot be in contact with the mandrel 424. Thus, the nipple 410 and themandrel 424 may define an annular space 470 (e.g., an annular gap orvolume) between the nipple 410 and the mandrel 424. The port 456 mayextend to or otherwise be fluidly connected (e.g., in fluidcommunication) with the annular space 470. The annular space 470 mayextend to or otherwise be fluidly connected with the internal space ofthe packer 416 between the mandrel 424 and the packer 416. The annularspace 470 between a radially and axially inward edge (e.g., the axialend 464) of the connector assembly 402 and the outer profile 452 of themandrel 424 may have a thickness ranging, for example, between aboutthree millimeters (mm) and about one mm or less.

The outer profile 452 of the mandrel 424, including one or more outersurfaces of the mandrel 424, may be substantially smooth (i.e.,substantially cylindrical and not include additional ports, depressions,holes, asperities, protrusions, and/or other irregularities) along alength of the mandrel 424 extending between the connector assemblies402, 404 (i.e., along a length of the mandrel 424 that is not surroundedby the connector assemblies 402, 404). The outer profile 452 of themandrel 424 may also or instead be substantially smooth along a lengthof the mandrel 424 between the port 456 and the connector assembly 404.Thus, the outer profile 452 of the mandrel 424 may be substantiallysmooth along a length of the mandrel 424 that is directly surrounded by,disposed against, or contacts moving portions of the packer 416.

The uphole portion 406 of the tool string may comprise a fluid pump 306(shown in FIG. 3) fluidly connected with a flowline 472 extendingaxially along the uphole portion 406 of the tool string. When theconnector assembly 402 is coupled with the uphole portion 406 of thetool string, the flowlines 458, 472 are fluidly connected to fluidlyconnect the pump 306 with the flowline 458 and the port 456.Accordingly, during downhole operations (e.g., fluid samplingoperations), the pump 306 may pump (i.e., discharge) an inflation fluidinto the packer 416 via the flowlines 472, 458, the port 456, and theannular space 470 to expand the packer 416 away from the mandrel 424against a sidewall of the wellbore or the casing within the wellbore.The pump 306 may also pump (i.e., draw) the inflation fluid out of thepacker 416 via the flowlines 472, 458, the port 456, and the annularspace 470 to retract the packer 416 away from the sidewall of thewellbore or the casing toward and/or into contact with the mandrel 424.

An anti-extrusion layer 474 may be disposed at an interface between theannular space 470 and the internal space of the packer 416. Theanti-extrusion layer 474 may be configured to prevent an inner layer(i.e., the elastic inner layer 440) of the packer 416 from being forcedinto and/or extruded through the annular space 470, which could damagethe inner layer when, for example, the hydrostatic pressure within thewellbore is greater than the pressure within the internal space of thepacker 416. The anti-extrusion layer 474 may surround the axially inwardend 464 of the connector assembly 402, including over the radially andaxially inward edge of the connector assembly 402, and a portion of theouter profile 452 of the mandrel 424 adjacent the end 464. Theanti-extrusion layer 474 may comprise a fluid permeable material, suchas a mesh, which may permit the inflation fluid to flow through theanti-extrusion layer 474, but prevent the elastic inner layer 440 fromentering the annular space 470. The anti-extrusion layer 474 may be orcomprise carbon fibers, KEVLAR fibers, and/or other fibers. Theanti-extrusion layer 474 may also or instead be or comprise a metallictube or sleeve. When comprising a non-permeable material, theanti-extrusion layer 474 may form a thin (e.g., thinner than the annularspace 470) annular gap or space between the anti-extrusion layer 474 andthe mandrel 424, such as may permit transfer of the inflation fluid intoand out of the internal space of the packer 416.

Although not shown, the packer tool 400 may comprise multiple instancesof the port 456 distributed circumferentially around the mandrel 424(i.e., along the surface of the mandrel 424), each located between theopposing ends 462, 464 of the connector assembly 402 and connected withthe flowline 458. Although not shown in detail, the downhole connectorassembly 404 may comprise a substantially similar configuration to theuphole connector assembly 402, comprising one or more ports, eachfluidly connected with the flowline 458 or another flowline extendingthrough the mandrel 424.

FIG. 5 further shows a port 476 (drawn in phantom lines) on an outersurface of the mandrel 424 and a flowline 478 (drawn in phantom lines)extending within the mandrel 424 and in fluid communication with theport 476. The port 476 and the flowline 478 are not part of the packertool 400, but are shown in FIG. 5 to indicate the location of the port476 in conventional packer tools. Namely, the port 476 is located alongthe mandrel 424 adjacent to the packer 416 such that when the packer 416is in the fully deflated (i.e., retracted) state, an inner surface ofthe packer 416 is disposed against and/or in contact with the port 476.Such location of the port 476 may cause the inner layer (e.g., theelastic inner layer 440) of the packer 416 to be forced into and/orextruded through the port 476, damaging the inner layer. Such situationmay take place when the hydrostatic pressure within the wellbore isgreater than the pressure within the internal space of the packer 416,for example, when the hydrostatic pressure is greater than the pressureof the inflation fluid within the flowline 478.

FIG. 6 is a schematic view of at least a portion of an exampleimplementation of a processing device 500 according to one or moreaspects of the present disclosure. The processing device 500 may form atleast a portion of one or more electronic devices utilized at thewellsite systems 100, 200. For example, the processing device 500 may beor form at least a portion of the surface equipment 190, 290 and/or thedownhole controller 150, 216. The processing device 500 may be incommunication with various sensors (e.g., pressure sensors, positionsensors, depth sensors), actuators (e.g., rotary table, top drive,pumps), local controllers, and other devices of the wellsite systems100, 200. The processing device 500 may be operable to receive codedinstructions 532 from human wellsite operators and sensor data generatedby the sensors, process the coded instructions 532 and the sensor data,and communicate control data to the actuators to execute the codedinstructions 532 to implement at least a portion of one or more examplemethods and/or operations described herein, and/or to implement at leasta portion of one or more of the example systems described herein.

The processing device 500 may be or comprise, for example, one or moreprocessors, special-purpose computing devices, servers, personalcomputers (e.g., desktop, laptop, and/or tablet computers), personaldigital assistants, smartphones, internet appliances, and/or other typesof computing devices. The processing device 500 may comprise a processor512, such as a general-purpose programmable processor. The processor 512may comprise a local memory 514, and may execute coded instructions 532present in the local memory 514 and/or another memory device. Theprocessor 512 may execute, among other things, the machine-readablecoded instructions 532 and/or other instructions and/or programs toimplement the example methods and/or operations described herein. Theprograms stored in the local memory 514 may include program instructionsor computer program code that, when executed by the processor 512 of theprocessing device 500, may cause the wellsite systems 100, 200,including the packer tools 300, 400, to perform the example methodsand/or operations described herein. The processor 512 may be, comprise,or be implemented by one or more processors of various types suitable tothe local application environment, and may include one or more ofgeneral-purpose computers, special-purpose computers, microprocessors,digital signal processors (DSPs), field-programmable gate arrays(FPGAs), application-specific integrated circuits (ASICs), andprocessors based on a multi-core processor architecture, as non-limitingexamples. Of course, other processors from other families are alsoappropriate.

The processor 512 may be in communication with a main memory 516, suchas may include a volatile memory 518 and a non-volatile memory 520,perhaps via a bus 522 and/or other communication means. The volatilememory 518 may be, comprise, or be implemented by random access memory(RAM), static random access memory (SRAM), synchronous dynamic randomaccess memory (SDRAM), dynamic random access memory (DRAM), RAMBUSdynamic random access memory (RDRAM), and/or other types of randomaccess memory devices. The non-volatile memory 520 may be, comprise, orbe implemented by read-only memory, flash memory, and/or other types ofmemory devices. One or more memory controllers (not shown) may controlaccess to the volatile memory 518 and/or non-volatile memory 520.

The processing device 500 may also comprise an interface circuit 524.The interface circuit 524 may be, comprise, or be implemented by varioustypes of standard interfaces, such as an Ethernet interface, a universalserial bus (USB), a third generation input/output (3GIO) interface, awireless interface, a cellular interface, and/or a satellite interface,among others. The interface circuit 524 may also comprise a graphicsdriver card. The interface circuit 524 may also comprise a communicationdevice, such as a modem or network interface card to facilitate exchangeof data with external computing devices via a network (e.g., Ethernetconnection, digital subscriber line (DSL), telephone line, coaxialcable, cellular telephone system, satellite, etc.). One or more of thelocal controllers, the sensors, and the actuators may be communicativelyconnected with the processing device 500 via the interface circuit 524,such as may facilitate communication between the processing device 500and the local controllers, the sensors, and/or the actuators.

One or more input devices 526 may also be connected to the interfacecircuit 524. The input devices 526 may permit the wellsite operators toenter the coded instructions 532, such as control commands, processingroutines, and/or operational set-points. The input devices 526 may be,comprise, or be implemented by a keyboard, a mouse, a joystick, atouchscreen, a track-pad, a trackball, an isopoint, and/or a voicerecognition system, among other examples. One or more output devices 528may also be connected to the interface circuit 524. The output devices528 may be, comprise, or be implemented by video output devices (e.g.,an LCD, an LED display, or a CRT display), printers, and/or speakers,among other examples. The processing device 500 may also communicatewith one or more mass storage devices 530 and/or a removable storagemedium 534, such as may be or include floppy disk drives, hard drivedisks, compact disk (CD) drives, digital versatile disk (DVD) drives,and/or USB and/or other flash drives, among other examples.

The coded instructions 532 may be stored in the mass storage device 530,the main memory 516, the local memory 514, and/or the removable storagemedium 534. Thus, the processing device 500 may be implemented inaccordance with hardware (perhaps implemented in one or more chipsincluding an integrated circuit, such as an ASIC), or may be implementedas software or firmware for execution by the processor 512. In the caseof firmware or software, the implementation may be provided as acomputer program product including a non-transitory, computer-readablemedium or storage structure embodying computer program code (i.e.,software or firmware) thereon for execution by the processor 512. Thecoded instructions 532 may include program instructions or computerprogram code that, when executed by the processor 512, may cause thewellsite systems 100, 200, including the packer tools 300, 400, toperform intended methods, processes, and/or operations disclosed herein.

FIG. 7 is a flow-chart diagram of at least a portion of an exampleimplementation of a method (600) for use of a conventional packer toolwithout the possibility of applying negative pressure. If packerdeflation is not efficient, there can be risks of sticking, or wastingtime in the wellbore. Moreover, there is no indication or sensor showingthat the packer deflation is sufficient.

The method (600) comprises running (610) (i.e., conveying) a tool stringwith an inflatable packer tool within a wellbore to a selected locationalong the wellbore, and then inflating (630) the packer tool against asidewall of the wellbore or a casing within the wellbore. A fluidsampling operation is then performed (640), after which the packer toolis deflated (650) by opening a relief valve to evacuate inflation fluidfrom the packer tool. The tool string is then moved (660) to the nextstation within the wellbore. This may be repeated 670 for multiple fluidsampling stations along the wellbore.

The present disclosure is further directed to one or more methodsaccording to one or more aspects of the present disclosure. The methodsdescribed below and/or other operations described herein may beperformed utilizing or otherwise in conjunction with at least a portionof one or more implementations of one or more instances of the apparatusshown in one or more of FIGS. 1-6 and/or otherwise within the scope ofthe present disclosure. However, the methods and operations describedherein may be performed in conjunction with implementations of apparatusother than those depicted in FIGS. 1-6 that are also within the scope ofthe present disclosure. The methods and operations may be performedmanually by one or more human operators, and/or may be performed orcaused, at least partially, by the processing device 500 executing thecoded instructions 532 according to one or more aspects of the presentdisclosure. For example, the processing device 500 may receive inputsignals and automatically generate and transmit output signals tooperate or cause a change in an operational parameter of one or morepieces of the wellsite equipment described above. However, the humanoperator may also or instead manually operate the one or more pieces ofwellsite equipment via the processing device 500 based on sensor signalsdisplayed.

FIGS. 8 and 9 are flow-chart diagrams of at least a portion of exampleimplementations of methods (700, 800) according to one or more aspectsof the present disclosure. With the aspects introduced above with regardFIGS. 1-6, forced deflation may be used to recover the initial outerdiameter of the expandable packers 316, 416 and ensure the toolstring isfree to be moved to the next station. During the deflation process,inner pressure within the packer 316, 416 may be similar to (e.g., thesame as or less than) the hydrostatic pressure within the wellbore.

The method (700) comprises running (710) a tool string with aninflatable packer tool 400 within a wellbore to a selected locationalong the wellbore. The packer 416 is then inflated (730) against asidewall of the wellbore or a casing within the wellbore by pumping orotherwise transferring an inflation fluid into the internal space of thepacker 416 through the flowlines 458, 472, the port 456, and the annularspace 470. After the packer 416 is inflated (730), a fluid samplingoperation may be performed (740). The packer 416 may then be deflated(750) such that the packer 416 fully retracts away from the sidewall toagainst the mandrel 424 by transferring substantially all of the fluidcontained within the packer 416 through the flowline 458, the port 456,and the annular space 470. The packer 416 may be deflated (750) bypumping out substantially all of the fluid contained within the packer416 with the pump 306. During deflation (750), the pressure of the fluidbeing pumped out of the packer 416 may be monitored or checked (760),and a drop in the pressure may be indicative that the packer 416 fullydeflated. After the packer tool has fully deflated (750), the toolstring may be moved (770) to the next station within the wellbore. Theabove may be repeated 780 for multiple fluid sampling stations along thewellbore.

It is noted that a full inflation/deflation cycle can lead to wastingtime in the wellbore, as well as additional rubber aging due to multipleelongation/compression cycles. Thus, for moving between stations but notrunning out of hole, the packer 416 may be partially deflated by, forexample, one third of inflation volume or otherwise sufficiently toensure that the packer tool 400 is free. This also decreases inflationtime at the following station. In order to recover the fully retractedoutside diameter before pulling the tool string out of hole, the packer416 may be fully deflated after the last station. In suchimplementations, the method (800) shown in FIG. 9 may be utilized.However, there would remain the possibility that partial deflation isnot sufficient to free the packer tool 400 between two stations, inwhich case full deflation of the packer 416 may be performed.

The method (800) comprises running (810) a tool string with aninflatable packer tool 400 within a wellbore to a selected locationalong the wellbore. After the packer tool 400 arrives at the selectedlocation along the wellbore, the packer 416 is inflated against asidewall of the wellbore or a casing within the wellbore by pumping aninflation fluid into the internal space of the packer 416 through theflowlines 458, 472, the port 456, and the annular space 470. A fluidsampling operation may then be performed. After the sampling operationis performed, the packer 416 may be partially deflated (820) such thatthe packer 416 partially retracts away (i.e., disengages) from thesidewall toward the mandrel 424. Such partial deflation (820) may be bypumping out a portion of the fluid contained within the packer 416through the flowlines 458, 472, the port 456, and the annular space 470.However, the packer 416 may be partially deflated (820) by opening afluid relief valve, whether instead of or in addition to pumping fluidout of the packer 416. After the packer tool is partially deflated(820), the tool string with the packer tool 400 may be moved to the nextstation within the wellbore. This may be repeated (830) for multiplefluid sampling stations along the wellbore.

The packer 416 may then be fully deflated (840) such that the packer 416fully retracts away from the sidewall to against the mandrel 424,whether by pumping and/or otherwise transferring substantially all ofthe fluid out of the packer 416 through the flowlines 458, 472, the port456, and the annular space 470. After the packer 416 is fully deflated(840), the tool string with the packer tool 400 may be pulled out of thehole (850).

During full deflation (750), (840), or otherwise when the pressure ofthe fluid within the packer 416 becomes less than the hydrostaticpressure within the wellbore, a portion (e.g., the sleeve 411 of thenipple 410) of the connector assembly 402 disposed over the port 456 mayprevent an inner layer (e.g., elastic inner layer 440) of the packer 416from being forced into and/or extruded through the port 456.

In view of the entirety of the present disclosure, including the claimsand the figures, a person having ordinary skill in the art will readilyrecognize that the present disclosure introduces an apparatus comprisingan inflatable packer assembly for coupling within a tool string conveyedwithin a wellbore, wherein the inflatable packer assembly comprises: (A)a mandrel comprising: (1) a port in an outer surface of the mandrel; and(2) a flowline extending within the mandrel and in fluid communicationwith the port; (B) a first connector assembly connected to the mandrelsuch that the port is axially disposed between opposing ends of thefirst connector assembly, wherein the first connector assembly is forcoupling with a first portion of the tool string such that a secondflowline of the first portion is in fluid communication with the firstflowline; (C) a second connector assembly for coupling with a secondportion of the tool string; and (D) an expandable packer disposed aroundthe mandrel and connected with the first and second connectorassemblies, such that fluid received from the first and second flowlinesvia the port expands the expandable packer against a sidewall of thewellbore or a casing within the wellbore.

The port may be a first port of a plurality of ports distributedcircumferentially around the mandrel.

An outer profile of the mandrel may be substantially smooth along alength extending between the port and the second connector assembly. Noadditional ports may exist along the length.

An outer profile of the mandrel may be substantially smooth along alength that contacts moving portions of the expandable packer.

An annular gap between a radially and axially inward edge of the firstconnector assembly and an outer profile of the mandrel may have athickness not greater than about three millimeters. An annular volumebetween an inner profile of the first connector assembly and the outerprofile of the mandrel may include the annular gap and may be in fluidcommunication with the port. The inflatable packer assembly may furthercomprise an anti-extrusion layer surrounding: an axially inward end ofthe first connector assembly, including over the radially and axiallyinward edge of the first connector assembly; and a portion of the outerprofile of the mandrel. The anti-extrusion layer may comprise a fluidpermeable material, carbon fibers, and/or KEVLAR fibers, and/or may be ametallic sleeve.

The present disclosure also introduces an apparatus comprising aninflatable packer assembly configured to be conveyed within a wellbore,wherein the inflatable packer assembly comprises: a first end assembly;a second end assembly; a mandrel extending between the first and secondend assemblies and comprising a fluid port on an outer surface of themandrel, wherein at least a portion of the first end assembly extendsaround the mandrel to define an annular space between the first endassembly and the mandrel, and wherein the fluid port extends to theannular space; and an expandable packer disposed around the mandrel andsealingly connected with the first and second end assemblies, whereinthe fluid port and annular space are configured to pass a fluid toinflate the expandable packer.

The fluid port may be a first fluid port of a plurality of fluid portsdistributed circumferentially around the outer surface of the mandrel.

A portion of an outer profile of the mandrel that extends between thefirst and second end assemblies and that is not surrounded by the firstend assembly may be substantially smooth and without additional ports.

A portion of an outer profile of the mandrel directly contacted by theexpandable packer may be substantially smooth and without additionalports.

The at least a portion of the first end assembly extending around themandrel may extend around the fluid port.

The annular space may have a thickness not greater than about threemillimeters.

An annular volume between an inner profile of the first end assembly andan outer profile of the mandrel may include the annular space and may bein fluid communication with the fluid port.

The inflatable packer assembly may further comprise an anti-extrusionlayer extending around: an axially inward end of the first end assembly,including over a radially and axially inward edge of the first endassembly; and a portion of an outer profile of the mandrel. Theanti-extrusion layer may comprise a fluid permeable material, carbonfibers, and/or KEVLAR fibers, and/or may be a metallic sleeve.

The present disclosure also introduces a method comprising: (A) couplingan inflatable packer assembly to a tool string, wherein the inflatablepacker assembly comprises: (1) a mandrel comprising: (a) a port in anouter surface of the mandrel; and (b) a first flowline extending withinthe mandrel and in fluid communication with the port; (2) a firstconnector assembly connected to the mandrel such that the port isaxially disposed between opposing ends of the first connector assembly;(3) a second connector assembly; and (4) an expandable packer disposedaround the mandrel and connected with the first and second connectorassemblies, wherein coupling the inflatable packer assembly to the toolstring comprises: (A1) coupling the first connector assembly with afirst portion of the tool string such that a second flowline of thefirst portion of the tool string is in fluid communication with thefirst flowline; and (A2) coupling the second connector assembly with asecond portion of the tool string; (B) conveying the inflatable packerassembly within a wellbore to a selected location along the wellbore;and (C) inflating the expandable packer away from the mandrel to againsta sidewall of the wellbore or a casing within the wellbore bytransferring a fluid into the expandable packer through the firstflowline, the second flowline, and the port.

The method may comprise performing a fluid sampling operation afterinflating the expandable packer against the sidewall.

The method may comprise partially deflating the expandable packer suchthat the expandable packer partially retracts away from the sidewalltoward the mandrel by transferring out of the expandable packer aportion the fluid contained by the expandable packer through the firstflowline and the port. In such implementations, among others within thescope of the present disclosure, the selected location may be a selectedfirst location, and the method may comprise, after partially deflatingthe expandable packer, conveying the inflatable packer assembly withinthe wellbore to a selected second location along the wellbore.

The method may comprise fully deflating the expandable packer such thatthe expandable packer fully retracts away from the sidewall to againstthe mandrel by transferring out of the expandable packer substantiallyall of the fluid contained by the expandable packer through the firstflowline and the port. In such implementations, among others within thescope of the present disclosure, fully deflating the expandable packersuch that the expandable packer fully retracts away from the sidewall toagainst the mandrel may comprise pumping out of the expandable packersubstantially all of the fluid contained by the expandable packer. Insuch implementations, among others within the scope of the presentdisclosure, the method may comprise monitoring pressure of the fluidbeing pumped out of the expandable packer, wherein a drop in themonitored pressure may be indicative that the expandable packer fullydeflated. A portion of the first connector assembly may be disposed overthe port, and during deflation of the expandable packer, when pressureof the fluid within the packer becomes less than hydrostatic pressurewithin the wellbore, the portion of the first connector assemblydisposed over the port may prevent an inner layer of the expandablepacker from being forced into the port.

The foregoing outlines features of several embodiments so that a personhaving ordinary skill in the art may better understand the aspects ofthe present disclosure. A person having ordinary skill in the art shouldappreciate that they may readily use the present disclosure as a basisfor designing or modifying other processes and structures for carryingout the same functions and/or achieving the same benefits of theimplementations introduced herein. A person having ordinary skill in theart should also realize that such equivalent constructions do not departfrom the spirit and scope of the present disclosure, and that they maymake various changes, substitutions and alterations herein withoutdeparting from the spirit and scope of the present disclosure.

The Abstract at the end of this disclosure is provided to permit thereader to quickly ascertain the nature of the technical disclosure. Itis submitted with the understanding that it will not be used tointerpret or limit the scope or meaning of the claims.

What is claimed is:
 1. An apparatus comprising: an inflatable packerassembly for coupling within a tool string conveyed within a wellbore,wherein the inflatable packer assembly comprises: a mandrel comprising:a port in an outer surface of the mandrel; and a flowline extendingwithin the mandrel and in fluid communication with the port; a firstconnector assembly connected to the mandrel such that the port isaxially disposed between opposing ends of the first connector assembly,wherein the first connector assembly is for coupling with a firstportion of the tool string such that a second flowline of the firstportion is in fluid communication with the first flowline; a secondconnector assembly for coupling with a second portion of the toolstring; and an expandable packer disposed around the mandrel andconnected with the first and second connector assemblies, such thatfluid received from the first and second flowlines via the port expandsthe expandable packer against a sidewall of the wellbore or a casingwithin the wellbore.
 2. The apparatus of claim 1 wherein an outerprofile of the mandrel is substantially smooth along a length extendingbetween the port and the second connector assembly.
 3. The apparatus ofclaim 2 wherein no additional ports exist along the length.
 4. Theapparatus of claim 1 wherein an outer profile of the mandrel issubstantially smooth along a length that contacts moving portions of theexpandable packer.
 5. The apparatus of claim 1 wherein an annular gapbetween a radially and axially inward edge of the first connectorassembly and an outer profile of the mandrel has a thickness not greaterthan about three millimeters.
 6. The apparatus of claim 5 wherein anannular volume between an inner profile of the first connector assemblyand the outer profile of the mandrel includes the annular gap and is influid communication with the port.
 7. The apparatus of claim 5 whereinthe inflatable packer assembly further comprises an anti-extrusion layersurrounding: an axially inward end of the first connector assembly,including over the radially and axially inward edge of the firstconnector assembly; and a portion of the outer profile of the mandrel.8. The apparatus of claim 7 wherein the anti-extrusion layer comprises afluid permeable material.
 9. The apparatus of claim 7 wherein theanti-extrusion layer comprises carbon and/or KEVLAR fibers.
 10. Theapparatus of claim 7 wherein the anti-extrusion layer is a metallicsleeve.
 11. An apparatus comprising: an inflatable packer assemblyconfigured to be conveyed within a wellbore, wherein the inflatablepacker assembly comprises: a first end assembly; a second end assembly;a mandrel extending between the first and second end assemblies andcomprising a fluid port on an outer surface of the mandrel, wherein atleast a portion of the first end assembly extends around the mandrel todefine an annular space between the first end assembly and the mandrel,and wherein the fluid port extends to the annular space; and anexpandable packer disposed around the mandrel and sealingly connectedwith the first and second end assemblies, wherein the fluid port andannular space are configured to pass a fluid to inflate the expandablepacker.
 12. The apparatus of claim 11 wherein the inflatable packerassembly further comprises an anti-extrusion layer extending around: anaxially inward end of the first end assembly, including over a radiallyand axially inward edge of the first end assembly; and a portion of anouter profile of the mandrel.
 13. A method comprising: coupling aninflatable packer assembly to a tool string, wherein the inflatablepacker assembly comprises: a mandrel comprising: a port in an outersurface of the mandrel; and a first flowline extending within themandrel and in fluid communication with the port; a first connectorassembly connected to the mandrel such that the port is axially disposedbetween opposing ends of the first connector assembly; a secondconnector assembly; and an expandable packer disposed around the mandreland connected with the first and second connector assemblies, whereincoupling the inflatable packer assembly to the tool string comprises:coupling the first connector assembly with a first portion of the toolstring such that a second flowline of the first portion of the toolstring is in fluid communication with the first flowline; and couplingthe second connector assembly with a second portion of the tool string;conveying the inflatable packer assembly within a wellbore to a selectedlocation along the wellbore; and inflating the expandable packer awayfrom the mandrel to against a sidewall of the wellbore or a casingwithin the wellbore by transferring a fluid into the expandable packerthrough the first flowline, the second flowline, and the port.
 14. Themethod of claim 13 further comprising performing a fluid samplingoperation after inflating the expandable packer against the sidewall.15. The method of claim 13 further comprising partially deflating theexpandable packer such that the expandable packer partially retractsaway from the sidewall toward the mandrel by transferring out of theexpandable packer a portion the fluid contained by the expandable packerthrough the first flowline and the port.
 16. The method of claim 15wherein the selected location is a selected first location, and whereinthe method further comprises, after partially deflating the expandablepacker, conveying the inflatable packer assembly within the wellbore toa selected second location along the wellbore.
 17. The method of claim13 further comprising fully deflating the expandable packer such thatthe expandable packer fully retracts away from the sidewall to againstthe mandrel by transferring out of the expandable packer substantiallyall of the fluid contained by the expandable packer through the firstflowline and the port.
 18. The method of claim 17 wherein fullydeflating the expandable packer such that the expandable packer fullyretracts away from the sidewall to against the mandrel comprises pumpingout of the expandable packer substantially all of the fluid contained bythe expandable packer.
 19. The method of claim 18 further comprisingmonitoring pressure of the fluid being pumped out of the expandablepacker, wherein a drop in the monitored pressure is indicative that theexpandable packer fully deflated.
 20. The method of claim 18 wherein aportion of the first connector assembly is disposed over the port, andwherein during deflation of the expandable packer, when pressure of thefluid within the packer becomes less than hydrostatic pressure withinthe wellbore, the portion of the first connector assembly disposed overthe port prevents an inner layer of the expandable packer from beingforced into the port.